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The main objective of this work is to understand the impact of fracture, stress, drilling direction and other reservoir properties on the production performance in horizontal well (HW). Taking advantage of seventy available borehole image logs helped to extend analysis beyond individual wells to a field scale evaluation. Three analysis techniques were developed to progress with the study: Digital Interpretation of Borehole Breakout in image log, Favored Drilling Direction Map, and a Reservoir Property Filter to gauge well performance. Results in cross plots showed complicated, cloudy and multi-dimensional relationships. The findings will be used to guide future HW drilling optimization, support dynamic modeling and improve models predictability for effective reservoir management.
- North America > United States (0.46)
- Asia > Kazakhstan > West Kazakhstan Region (0.29)
- Phanerozoic > Paleozoic > Permian (0.94)
- Phanerozoic > Paleozoic > Devonian (0.68)
- Geology > Structural Geology > Tectonics (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock (0.93)
- (2 more...)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.61)
- North America > United States > California > San Joaquin Basin > Lost Hills Field (0.99)
- North America > United States > California > Monterey Formation (0.99)
- Asia > Kazakhstan > West Kazakhstan > Uralsk Region > Precaspian Basin > Karachaganak Field (0.99)
- (5 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (0.93)
- (5 more...)
ABSTRACT This paper presents a quantitative evaluation of the effect of mechanical stratigraphy on induced hydraulic fracture shape and extent. A detailed geomechanical and hydrodynamic model was built for Hydraulic Fracture Test Site 1 (HFTS-1) in the Permian Basin, considering available geomechanical, geological and geophysical characterization data. This model was then implemented using a discrete fracture network (DFN) approach, to facilitate simulation of induced (tensile) hydraulic fractures, and reactivation of pre-existing natural fractures. INTRODUCTION The geometry of natural and induced tension cracks is important to civil, mining, geothermal, and energy applications. According to Griffith Crack theory for failure of brittle materials (Griffith, 1921), natural and induced tension cracks in an infinite, homogeneous, isotropic medium are circular or elliptical. Over 100 years of laboratory studies have provided empirical support for this theory. However, extensive evidence from microseismic monitoring and offset well intersections indicates that the shape of in situ hydraulic fractures vary considerably from the elliptical ideal. GEOMECHANICAL STRATIGRAPHY Mechanical stratigraphy refers to the subdivision of a layered rock mass into distinct units (mechanical units) that reflect internally consistent rock properties and styles of deformation (Laubach et al., 2009). In response to tectonic deformation, elements of mechanical layering often control fracture dimensions, terminations and failure mode (Gross et al., 1995, 1997; Ferrill et al., 2014). This mechanical behavior occurs across many scales, and for an unconventional oil and gas field is manifested by hydraulic fracture lengths considerably greater than their heights (Fu et al., 2022), an indication that anisotropic layering limits the vertical growth of hydraulic fractures (i.e., serve as frac barriers). Observations of natural fractures in outcrops provide insight into the growth and geometry of induced hydraulic fractures in the subsurface (Lacazette and Engelder, 1992; Engelder, 2004; Engelder et al., 2009). Surface morphology preserved on opening-mode fractures ("joints") are manifestations of fracture initiation, propagation and arrest, as demonstrated in Figure 1. In this siltstone bed from the Appalachian Plateau in upstate New York, lineations on the fracture surface converge backwards to the initiation point (yellow dot), about one-third of the way above the bottom of the bed. The lineation pattern shows the joint grew radially in all directions, until it reached the bottom and top of the bed.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.35)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
Description Geologic feature : Polygonal faulting and pockmarks in the Great South Basin New Zealand Appearance : Dense faulting among horizons in cross section and reflector concave features in seismic sections Map view appearance : Dense faulting and multiple circular features Features with a similar appearance : Tectonic faulting, mounds, syneresis, carbonate mounds, and dissolution features Formation : Rakiura Group, offshore, Great South Basin, southern New Zealand Location : Great South Basin, southern side of the Southern Island in New Zealand Age : Eocene Data sets : A 3D seismic reflection data, from New Zealand Petroleum and Minerals (NZP&M), New Zealand Seismic attributes: Variance, curvature, dip magnitude, and color blending
- North America > United States (1.00)
- Oceania > New Zealand > South Island > South Pacific Ocean (0.41)
- Geology > Structural Geology > Fault (1.00)
- Geology > Sedimentary Geology (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.94)
- (3 more...)
- Geophysics > Seismic Surveying > Seismic Interpretation (1.00)
- Geophysics > Seismic Surveying > Seismic Processing (0.68)
- South America > Brazil > Espírito Santo > Espirito Santo Basin (0.99)
- Oceania > New Zealand > South Island > South Pacific Ocean > Great South Basin (0.99)
- North America > United States > California > Monterey Formation (0.99)
- (9 more...)
Quantifying Crack Properties of Source Rocks from Elastic Stress Sensitivity
Ding, Jihui (Stanford University) | Clark, Anthony C. (Stanford University) | Vanorio, Tiziana (Stanford University) | Jew, Adam D. (SLAC National Accelerator Laboratory) | Bargar, John R. (SLAC National Accelerator Laboratory)
Abstract In unconventional reservoirs, fractures provide primary flow pathways for hydrocarbon production. Extracting and understanding fracture properties are essential for stimulation optimization and production management. In this study, we propose a rock physics model to quantify fracture compliance and orientation distribution from the stress dependence of ultrasonic velocities measured on dry and fluid-saturated hydrocarbon source rocks. Based on the Sayers and Kachanov (1995) treatment of compliant discontinuities (broadly termed as cracks) in transversely isotropic media, we derived formulae that relate crack properties with acoustic velocities measured at varying orientations and pressures. Our modeling applies an approach similar to that of Pervukhina et al. (2011) except that a step function with variable width, instead of a continuous function of fixed width, is used to describe the distribution of crack orientations. Easing the restriction on the crack distribution width facilitates a more realistic representation of crack orientation anisotropy. We applied our model to organic-rich source rocks to quantify physically-meaningful crack properties, including normal-to-tangential compliance ratio and maximum dip angle relative to bedding. Our modeling results confirm that the compliance ratio is sensitive to fluid. Fluid-saturated rocks exhibit a lower compliance ratio than that of dry rocks, which is usually less than 1 and close to 0. This behavior is consistent with a fluid stiffening effect that reduces fracture normal compliance. The maximum dip angle decreases with depth, which suggests that cracks are more aligned with bedding at greater depth. The proposed model allows direct quantification of crack properties from rock physics experiments and provides important insights into the stress-dependent behavior of cracks. Thus, it could be a useful tool for understanding fracture behavior and its impact on stimulation and production of unconventional resources. Introduction Fractures are common in the subsurface and control the mechanical and transport behavior of rock formations. In unconventional reservoirs, fractures provide primary flow pathways for hydrocarbon production. Extracting and understanding the physical properties of fractures have been important geophysical tasks for developing unconventional resources. For such purposes, seismic waves have been a powerful tool both in the field and in laboratory. As elastic waves propagate through a fractured medium, they carry a wealth of information about fracture properties. While field-scale seismic surveys are often difficult to interpret due to complex geologic factors, acoustic waves can be measured in the laboratory at well-controlled conditions, such as effective pressure, wave propagation direction, and fluid saturation. Various rock physics models have been proposed to quantify fracture properties from the measured stress sensitivity of acoustic velocities. These models provide important insights into fracture behavior. For example, the normal-to-tangential compliance ratio of a fracture has been shown to frequently deviate from one - a value that is associated with specific fracture geometry and assumed in some fracture models. The crack compliance ratio is also confirmed to be sensitive to fluid in the fractures (Sayers, 1999; Lubbe et al., 2008). While other approaches have been proposed to model elastic stress sensitivity (e.g., Prioul et al, 2004; Shapiro, 2017), Pervukhina et al. (2011) developed a model for transversely isotropic (TI) medium based on Sayers and Kachanov (1995) treatment of compliant discontinuities (broadly termed as "cracks"). Their model does not assume specific crack geometry, outputs physically-meaningful parameters, and allows straightforward parameter fitting on experimental data. Despite these advantages, the crack orientation distribution function in their model does not capture the strong alignment of cracks. Crack orientation is an important crack property that impacts fluid flow and seismic anisotropy, and misrepresentation of its distribution could affect the accuracy of quantifying other crack properties.
- North America > United States > Texas (0.28)
- North America > United States > North Dakota (0.28)
- Geology > Rock Type > Sedimentary Rock (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Geochemistry (0.95)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.86)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation (0.99)
- (7 more...)
Abstract Extensive dolomitization is prevalent in the platform and periplatform carbonates in the Lower-Middle Permian strata in the Midland and greater Permian Basin. Early workers have found that the platform and shelf-top carbonates were dolomitized, whereas slope and basinal carbonates remained calcitic, proposing a reflux dolomitization model as the possible diagenetic mechanism. More importantly, they underline that this dolomitization pattern controls the porosity and forms an updip seal. These studies are predominately conducted using well logs, cores, and outcrop analogs, and although exhibiting high resolution vertically, such determinations are laterally sparse. We have used supervised Bayesian classification and probabilistic neural networks (PNN) on a 3D seismic volume to create an estimation of the most probable distribution of dolomite and limestone within a subsurface 3D volume petrophysically constrained. Combining this lithologic information with porosity, we then illuminate the diagenetic effects on a seismic scale. We started our workflow by deriving lithology classifications from well-log crossplots of neutron porosity and acoustic impedance to determine the a priori proportions of the lithology and the probability density functions calculation for each lithology type. Then, we applied these probability distributions and a priori proportions to 3D seismic volumes of the acoustic impedance and predicted neutron porosity volume to create a lithology volume and probability volumes for each lithology type. The acoustic impedance volume was obtained by model-based poststack inversion, and the neutron porosity volume was obtained by the PNN. Our results best supported a regional reflux dolomitization model, in which the porosity is increasing from shelf to slope while the dolomitization is decreasing, but with sea-level forcing. With this study, we determined that diagenesis and the corresponding reservoir quality in these platforms and periplatform strata can be directly imaged and mapped on a seismic scale by quantitative seismic interpretation and supervised classification methods.
- North America > United States > Texas (1.00)
- North America > United States > New Mexico (1.00)
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
- Geophysics > Seismic Surveying > Seismic Interpretation (1.00)
- Geophysics > Seismic Surveying > Surface Seismic Acquisition (0.86)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling > Seismic Inversion (0.49)
- North America > United States > Texas > Tobosa Basin (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (34 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- (2 more...)
Multistage unidirectionally migrating canyons and the evolution of their trajectories in the canyon zone in the Baiyun Sag, northern South China Sea: Insights into canyon genesis
Fu, Chao (China University of Geosciences, Université de Rennes 1) | Yu, Xinghe (China University of Geosciences) | Li, Shunli (China University of Geosciences) | Shan, Xin (Ministry of Natural Resources) | He, Yulin (Guangzhou Marine Geological Survey) | Jin, Lina (Nanjing University)
Abstract In deep-sea slope areas, canyons provide an ideal space to preserve sediments and provide a window to explore the deepwater deposition process, such as turbidity flow and contourite currents. We have evaluated results of the study of the northern continental slope of the South China Sea characterized by the presence of mostly straight canyons. After evaluating core samples and interpreting the corresponding seismic data, we static the sedimentary parameter and identified two types of canyons with different migrating trajectories: “convex downward curve-shaped” trajectories and “convex upward curve-shaped” trajectories. The convex downward curve-shaped canyon trajectory is distinguished by a lower layer of coarse-grained sediment and an upper layer of fine-grained sediment, whereas the convex upward curve-shaped canyon trajectory features a lower layer of fine-grained sediment and an upper layer of coarse-grained sediment. Combining the grain size of the core sample and the scale of the sedimentary structure, we restore the turbidity flow rates and the corresponding turbidity flow behaviors. Coarse-grained turbidity flows are characterized by lower vertical erosion rates and higher lateral abrasion rates, whereas fine-grained turbidity flows exhibit the opposite characteristics. Thus, the convex downward curve-shaped migration trajectory is mainly formed by coarse-grained turbidity flow erosion in the first stage (the late migration stage) and fine-grained turbidity flow deposition in the second stage (the vertical aggradation stage). In contrast, the convex upward curve-shaped trajectory forms through the opposite pattern of sedimentary evolution.
- Asia > China (1.00)
- North America > United States (0.93)
- Phanerozoic > Cenozoic > Paleogene (0.93)
- Phanerozoic > Cenozoic > Neogene > Miocene (0.47)
- Geophysics > Borehole Geophysics (0.94)
- Geophysics > Seismic Surveying > Seismic Processing (0.93)
- North America > United States > New Mexico > Permian Basin > Brushy Canyon Formation (0.99)
- North America > United States > California > Monterey Formation (0.99)
- Asia > China > South China Sea > Zhujiangkou Basin (0.99)
- (4 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (0.96)
Abstract An important aspect of exploration and development of unconventional reservoirs is understanding controls on the acoustic properties in organic rich shales to improve interpretation of prospective reservoirs through seismic. Dynamic elastic properties derived from velocities on a continuous interval can be used to target ideal facies for a more effective frac design (i.e. total organic content, thermal maturity and elastic properties). Studies that have examined organic rich shale properties at multiple scales have successfully correlated kerogen content and thermal maturity with acoustic velocities and anisotropy. However, discrete acoustic velocity variations associated with kerogen type and thermal maturity remain unclear. A scanning acoustic microscope is used to measure high resolution acoustic velocities on discrete laminae of variable organic content, type and maturity in unconventional samples. We infer that for unconventional reservoirs, in which typical particle and pore sizes are substantially smaller than 20 microns (i.e. resolution of a 20MHz probe), the difference in travel time between the first arrivals from the top and bottom surfaces of the sample provides an accurate measure of the velocity. A Backus average of the measured velocities of each layer type agrees well with laboratory measurements made at the core plug scale. Velocity measurements are integrated with micro-CT, thin section, XRF and SEM to identify presence and distribution of kerogen and mineral phases in the matrix (i.e. load bearing vs isolated). One-inch diameter core plugs are first micro-CT scanned and their acoustic properties are measured as received. After CT scanning, thin sections, acoustic microscope discs and SEM mounts are prepared. The end trim is ion milled in preparation for SEM and acoustic microscopy. Large area image mosaics are produced using low voltage SE imaging for characterizing porosity, and BSE imaging for characterization of organic content and mineralogy. Scanning CL imaging and image analysis are utilized to differentiate between detrital and authigenic phases. Energy dispersive x-ray mapping is also used for the identification of major mineral phases. The resulting suite of mosaic images are analyzed using UH-developed image analysis software. Segmented volumes of porosity, TOC, and mineral phases are determined for each layer type in the sample. We illustrate the relationship between segmented porosity, TOC, and mineralogy on the acoustic properties of each layer type. Mineral phases included in the modeling are clay minerals, pyrite, carbonate, and quartz. We include, where possible, the differentiation of authigenic quartz and carbonate phases. Velocities for each layer type are mapped to the microCT data for the core plug. We illustrate the technique applied in several highly heterogeneous formations including the Niobrara, Haynesville, Barnett, Woodford, and Eagle Ford.
- North America > United States > Texas (0.46)
- North America > United States > Oklahoma (0.28)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.46)
- Geology > Mineral > Silicate > Tectosilicate > Quartz (0.45)
- North America > United States > Texas > Haynesville Shale Formation (0.99)
- North America > United States > Louisiana > Haynesville Shale Formation (0.99)
- North America > United States > California > Monterey Formation (0.99)
- (9 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- (3 more...)
Abstract Drilling and reaching to deeper target zones through an overpressured overburden formation in a structurally complex geologic setting requires robust geologic and geomechanical analysis to mitigate risk and control operational costs. These types of geologic conditions are present in the Krishna-Godavari Basin, where a series of horst and grabens defined by deep-seated faults and persistent high sedimentation rates through geologic time, result in the development of challenging conditions for exploratory drilling. We have developed possible overpressure mechanisms across the central part of the Krishna-Godavari Basin and its interplay through fault-related lateral pressure transfer. The basin sits over a horst, which is one of the many northeast–southwest-trending en echelon horst and graben structures comprising sediments from the lower Cretaceous to Holocene. In the study area, Paleocene formations in the horst are overpressured (12–12.2 ppg). Three wells were drilled through this formation and reached the target without any drilling issues in the central and eastern part. However, the same formation in the western part of the horst (adjacent to the graben) has higher overpressure of approximately 14 ppg, which complicates the drilling operations because it requires an additional intermediate casing to reach the target reservoir safely. A detailed analysis of the overpressure mechanisms across the horst area to the adjacent deep graben revealed that the disequilibrium compaction signatures are related to the burial history and overburden thickness. The major difference between horst and graben area is the magnitude of overpressure, with an average of 16 ppg across the graben area. The larger overpressures experienced toward the western part of the horst indicate a secondary source of pressure from the adjacent deep graben. The fault stress analysis in this region presents a feasible lateral pressure transfer through critically stressed faults/fractures from the deep graben to the western part of the horst structure. The current model accounts the common pore pressure estimation method along with other critical geologic information to predict such overpressure related challenges in the upcoming future wells in a similar geologic setup to plan safe and cost-effective wells.
- Phanerozoic > Mesozoic > Cretaceous (0.69)
- Phanerozoic > Cenozoic > Paleogene > Paleocene (0.53)
- Phanerozoic > Cenozoic > Quaternary (0.48)
- Geology > Structural Geology > Tectonics > Extensional Tectonics (1.00)
- Geology > Structural Geology > Fault > Dip-Slip Fault > Normal Fault (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.48)
- Geophysics > Seismic Surveying (0.70)
- Geophysics > Borehole Geophysics (0.68)
- Oceania > Australia > Western Australia > Perth Basin (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- (15 more...)
- Well Drilling > Casing and Cementing > Casing design (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- (2 more...)
ABSTRACT In situ P- and S-wave velocity measurements in a variety of organic-rich shales exhibit P-to-S-wave velocity ratios that are significantly lower than lithologically similar fully brine-saturated shales having low organic content. It has been hypothesized that this drop could be explained by the direct influence of kerogen on the rock frame and/or by the presence of free hydrocarbons in the pore space. The correlation of hydrocarbon saturation with total organic content in situ makes it difficult to separate these possible mechanisms using log data alone. Theoretical bounding equations, using pure kerogen as an end-member component without associated gas, indicate that kerogen reduces the P- and S-wave velocities but does not in general reduce their ratio enough to explain the observed low velocity ratio. The theoretical modeling is consistent with ultrasonic measurements on organic shale core samples that indicate no dependence of velocity ratios on the kerogen volume alone. Sonic log measurements of P- and S-wave velocities in seven organic-rich shale formations deviate significantly (typically more than 5%) from the Greenberg-Castagna empirical brine-saturated shale trend toward lower velocity ratios. In these formations, and on core measurements, Gassmann fluid substitution to 100% brine saturation yields velocity ratios consistent with the Greenberg-Castagna velocity trend for fully brine-saturated shales, despite the high organic content. These sonic and ultrasonic measurements, as well as theoretical modeling, suggest that the velocity ratio reduction in organic shales is best explained by the presence of free hydrocarbons.
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (1.00)
- Geophysics > Borehole Geophysics (1.00)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (48 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- (3 more...)
Effect of anisotropy, angle, and critical tensile stress and confining pressures on evaluation of shale brittleness index — Part 1: Methodology and laboratory study
Wang, Qing (Beijing Information Science and Technology University) | Zhang, Bo (The University of Alabama) | Guo, Shiguang (Beijing Information Science and Technology University) | Han, Jianguang (Chinese Academy of Geological Sciences)
Abstract Brittleness is an important evaluation parameter in shale fracturing. Current methods of brittleness evaluation can be classified into two categories: elastic parameter-based and mineral content-based methods. However, both categories neglect the effect of anisotropy on the brittleness index (BI) computation of shale resources. We have redefined a new BI by integrating failure criteria stress and anisotropy parameters estimated (BIac) from seismic waves. According to the new definition, the BI at one analysis point varies with the incident angle of the seismic wave and confining pressures. We applied the BIac method to laboratory-measured shale samples acquired from the Monterey Formation, Santa Maria Basin. We found that the delta parameter is more responsive to the BIac than the gamma and epsilon anisotropic parameters, and it indicates a good linear fit relationship with the BIac at different angles. The slope of the linear is variable with the angles, thus delta can be used to predict the BIac in the Monterey Formation, Santa Maria Basin.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > California > Santa Maria Basin (0.99)
- North America > United States > California > Monterey Formation (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)